Self-breaking foamed oil in water emulsion for stimulation of wells blocked by paraffinic deposits

ABSTRACT

A self-breaking, foamed, oil-in-water emulsion contains a water-immiscible organic solvent for paraffins and asphaltenes, an aqueous nonformation-damaging component, an inert gas, and surface active agents selected to promote a stable foamed emulsion despite contact of the treating fluid with the hydrocarbon and aqueous environment in the reservoir. Under conditions of agitation, the treating fluid is a stable foamed emulsion which undergoes spontaneous breakdown into two liquid phases under quiescent conditions. The treating fluid is injected and/or circulated as a stable foamed emulsion to dissolve paraffin and asphaltene-containing deposits from various substrata, such as a subterranean reservoir penetrated by a well, the well itself, or an industrial vessel or conduit. When injection or circulation is stopped, the foamed emulsion spontaneously breaks down so that the treating fluid can be readily pumped from the well.

This application is a division of application Ser. No. 614,976, filedMay 29, 1984, now U.S. Pat. No. 4,614,236.

BACKGROUND OF THE INVENTION

This invention relates to the treatment of a subterraneanpetroleum-containing formation penetrated by a well with a treatingfluid capable of dissolving materials present in or on the substrata.More particularly, this invention relates to the treatment of a well orsubterranean formation to remove petroleum waxes commonly known as"paraffin deposits," which may contain asphaltene components, toincrease the permeability therethrough. This invention also relates tothe cleaning of industrial vessels and conduits to remove paraffindeposits therefrom.

In the course of producing certain types of petroleum oils and gasesfrom subterranean formations penetrated by a well, paraffins andasphaltenes deposited from the oil tend to clog the pores of thereservoir rock, the well casings, and the tubings and screens throughwhich the oil and gas flow to the surface. The deposition of paraffinsmay proceed to the point that production is completely interrupted.

In the past, the problem of removing paraffin deposits has beenapproached in various ways. The oldest method, and perhaps the mosteffective heretofore, was to clean the wellbore mechanically, as forexample, by scraping. This method, however, was too expensive to beeconomically feasible as it resulted in lost production time, additionalrig time, and high costs for labor and mechanical tools. Moreover,scraping could not reach deposits left behind the well casing or withinthe producing formation.

Another common practice to remove paraffin deposits employs chemicalsolvents to restore flow to a plugged formation and wellbore. Solventscustomarily used to dissolve paraffins and asphaltenes include benzenederivatives, gasoline, distillates, carbon tetrachloride and carbondisulfide. Usually hot oil or solvent is injected as a liquid todissolve the paraffins and other soluble hydrocarbons. But removal ofsoluble paraffins and other hydrocarbons by solvent injection poses twoproblems. First, the condition of the well may actually be worsened ifinsoluble, soil-like constituents of the sludge fouling the well remainbehind after the treatment in higher concentrations than before thesolvent injection was performed. Second, solvents may become excessivelydiluted during injection by contamination with reservoir fluids beforethey reach the zone of plugging since paraffins form in the lowerportion of the well.

Other methods of removing paraffins from producing wells require heatgeneration in situ to dissolve the paraffinic components of deposits.The method used may rely upon heat generated by the exothermicneutralization reaction of alternately administered slugs of acid andbase solutions. Or a hot, foamed detergent may be generated in situ byadministering alternate slugs of alkali metasilicate, or similardetergents, and concentrated sulfuric acid solutions containing a foamstabilizer. The latter method is disclosed in U.S. Pat. No. 4,089,703 toWhite.

One of the most effective solvents for paraffins of varying compositionsis carbon disulfide. But carbon disulfide is difficult and hazardous touse because it is highly toxic, flammable, and volatile. As it is alsoreadily soluble in oil, carbon disulfide is difficult to place deep intowells containing a standing column of oil. To reduce the hazardsassociated with using carbon disulfide, Rowlinson in U.S. Pat. No.3,375,192 discloses a mixture for use in cleaning oil wells comprising 8to 16 volume percent of pentane and the balance of carbon disulfide. Thepentane is used to raise the ignition temperature of the carbondisulfide and thereby reduce the fire hazard associated with its use.

U.S Pat. No. 3,241,615 to Bertness discloses a process of removinghydrocarbon accumulation from within the wellbore by contacting thesubstrata with a liquid mixture comprising a surfactant and a solventsuch as carbon disulfide and flushing with water to disperse theparaffins. A mixture of water with the solvent-surfactant solution isalso contemplated.

Solvent emulsions have also been employed to remove paraffins fromplugged wellbores and oil well tubings. In U.S. Pat. No. 2,358,665 toShapiro, a method is described in which oil immiscible solvent emulsionshaving a specific gravity greater than oil sink through the oil columnuntil, having reached the temperature at which they become unstable,they break, releasing the undiluted solvent to dissolve the waxes uponcontact. This method solves the problem of getting the solvent into thelower region of the oil column without dilution, but makes release ofthe solvent depend upon the temperature profile in the reservoir. Amethod to remove dependence of the point of solvent release upontemperature in the wellbore is disclosed in U.S. Pat. No. 3,724,553 toSnavely. A thermally stable oil-in-water emulsion of a mixture ofsolvents for paraffins is broken to release the solvents by contactingthe aqueous phase with salt injected into the well either before orafter injection of the emulsion. However, this method possesses thedisadvantage of potential damage to the reservoir from the addition ofsalts.

Foams minimize the volume of treating fluid required whilesimultaneously reducing the density of the treating fluid. A foamingagent and a gas are commonly added to a liquid treating fluid to form arelatively large volume of foamed treating fluid from a small amount ofsolvent and additives. U.S. Pat. No. 3,572,439 to Hutchinson et al.discloses a preformed well circulation foam containing water orwater-cosolvent mixtures stabilized by ammoniated concentrates oforganic foaming agents. Use of a mixture of foaming agents is alsocontemplated.

Generation and maintenance of foam is not difficult when the fluid to becontacted or displaced is either water or a variety of brines. Contactwith crude oil, however, depresses many foams. On the other hand,water-free foamed solvents often form viscous water-in-oil emulsionsupon contact with water. Use of a foamed solvent, therefore, may causeblocking of the formation in situ when it mixes with reservoir waters,and removal of the emulsion from the wellbore may prove difficult.

The use of oil-in-water emulsions may also be injurious to certainformations that contain clays or bentonitic shale. Introduction offoreign water into an argillaceous reservoir causes certain clays andbentonitic shales to swell due to ion exchange between non-ionicallybalanced injection water and the formation. Since swelling is pHsensitive, it is well known to acidify foreign waters to counteract theloss in permeability which results from such swelling. However, acidicwaters, even if used in solvent emulsions, pose the disadvantage ofbeing extremely corrosive to metal unless expensive corrosion inhibitorsare added.

Certain reservoir formations containing iron-bearing minerals are alsodamaged by deposition of iron-bearing precipitates within the formationif a solvent-containing fluid useful for removing paraffin deposits isused in conjunction with an acidic component for dissolving carbonate orsilicate deposits. Acidification of solvent-containing fluids is commonsince carbonates and iron-containing minerals are among the depositsmost commonly dissolved from wells. However, at the wellbore pressuresnecessary to prevent blowouts in active reservoirs, stimulation fluidstravel outwardly from the wellbore into the formation. Carbonates andiron-bearing components dissolved by the acidic components in thewell-treating fluid travel outwardly from the well and tend toprecipitate from solution as the travelling fluid contacts basicelements in the formation or becomes diluted with formation waters. Incertain clay or sandstone formations containing iron-bearing minerals,such as chlorite, or iron carbonates, such as ferroin, ferroin dolomite,and siderite, an acid component in the treating fluid results inredeposition of iron materials at locations deeper in the reservoirwhich have been dissolved from plugging components near the wellbore.

Interest has long been shown in developing an economical composition forstimulating production in low pressure stripper wells blocked byparaffin deposits. Stripper wells are characterized by depletedformation pressures caused by extended production. High density treatingfluids therefore create wellbore pressures sufficient to result inexcessive loss of treatment fluids into the formation during treating.Moreover, sludge remaining after paraffins and asphaltenes have beendissolved can be forced deep into the formation by the higher pressurein the wellbore and result in severe plugging difficult to reach bysubsequent cleaning procedures. If the treating fluid is also acidifiedto dissolve carbonates and silicates, iron-bearing deposits canreinforce the plug in the formation and virtually close in thereservoir.

The need has long been felt in the art for an inexpensive and effectivewell treating fluid useful for dissolving paraffin deposits which isneither explosive nor dependent upon the thermal gradient in thereservoir, and which will not cause salt damage to the formation by ionexchange with clays contained therein. Additionally, a compositionuseful for dissolving paraffin deposits from formations containingiron-bearing minerals that will not cause redeposition within thereservoir of iron containing deposits has long been sought in the art.

It is an object of this invention to provide a composition comprising afoamed oil-in-water emulsion of solvent in non-formation damagingaqueous solution which is useful for cleaning paraffin deposits from thewellbore, formation rock, or gravel pack of wells without damage to thesurrounding formation.

It is a further object of this invention to provide a cost-efficientmethod of removing paraffin deposits in which the volume of solvent usedto dissolve a given quantity of paraffin deposits is minimized and lossto the formation of the stimulation fluid is avoided.

An additional object of this invention is to provide a low density,foamed solvent emulsion which is stable while removing paraffin depositsfrom the wellbore and surrounding formations under agitated conditionsbut which breaks down spontaneously under quiescent conditions to form aliquid phase easy to remove from the wellbore.

Yet another object of this invention is to provide a method for removingparaffin deposits from depleted stripper wells in which formationpressure is used to assist in cleaning the residue of dissolved depositsfrom the well.

It is still another object of this invention to provide a foamed solventemulsion that maintains a stable viscosity during injection andcirculation when crude oil or formation water is contacted or whenasphaltenes and other natural emulsifiers are dissolved duringtreatment.

Additional objects, advantages and features of the invention will becomeapparent to those skilled in the art from the following description.

SUMMARY OF THE INVENTION

Briefly, this invention provides a composition for removing paraffinichydrocarbon deposits from subterranean locations such as formation rock,wellbores, or gravel pack of wells, said composition comprising (a) anorganic solvent for paraffins, (b) an aqueous liquid component, (c) aninert gas, and (d) a surface active agent.

Alternatively a composition for removing paraffinic hydrocarbon depositsfrom subterranean locations pentrated by a wellbore comprises (a) anorganic solvent for paraffins, (b) an aqueous liquid component, (c) aninert gas, and (d) sufficient of a surface active agent to maintain saidcomposition as a foamed oil-in-water emulsion under conditions ofagitation, but to allow spontaneous degassing and separation of saidcomposition into two substantially continuous liquid phases uponstanding.

In another embodiment, a composition useful for dissolving paraffinichydrocarbon deposits from subterranean locations penetrated by awellbore is provided, said composition comprising (1) a continuousnonacidic aqueous phase having non-reservoir damaging properties, (2) adiscontinuous solvent phase immiscible with said aqueous phase, saidsolvent being effective for dissolving paraffins, (3) a discontinuousgaseous phase comprising inert gas, and (4) sufficient of a surfaceactive agent selected to maintain said composition as an emulsion underconditions of agitation but to allow separation of the composition intotwo continuous liquid phases under conditions of quiescence.

In yet another embodiment, a foamed oil-in-water emulsion for cleaningparaffin deposits from subterranean locations penetrated by a wellboreis provided, said foamed emulsion comprising an organic solvent forparaffins and a non-acidic aqueous liquid containing not less than 2,000ppm by weight of dissolved ionic components, and sufficient of a surfaceactive agent selected to maintain the stability of said foamed emulsionunder conditions of agitation while allowing said foamed emulsion todegas and separate into two substantially continuous liquid phases underrelatively quiescent conditions.

The well treatment fluid referred to above is formed by a process thatcomprises (1) emulsifying finely divided droplets of ahydrocarbon-dissolving solvent in a continuous aqueous phase havingnon-reservoir-damaging properties to form an oil-in-water emulsion, and(2) forming a stable foam from the emulsion by turbulently contactingthe foam with a stream of inert gas, the foamed emulsion maintainingstability under conditions of agitation and undergoing relatively rapidand substantial breakdown into two liquid phases under conditions ofrest. The preferred way to disperse the droplets in step (1) and to formthe foam in step (2) is by adding at least one surface active agentpartially soluble in said continuous aqueous phase.

The foamed treating emulsion can be used to increase the permeability ofsubterranean reservoirs and filter media present in wells penetratingsuch subterranean reservoirs, and to remove paraffin deposits fromindustrial vessels and conduits.

DETAILED DESCRIPTION OF THE INVENTION

The present invention is directed to foamed emulsion compositions fordissolving paraffin-containing and/or paraffin and asphaltene-containingmaterials, and to methods for using such compositions. The inventionfinds its primary utility in treating subterranean formations, wellcasings, and the like, which are plugged or contain substantial depositsof a paraffinic character. In a specific embodiment of the invention, tobe described in greater detail hereinafter, the method and compositionsof the invention are useful in treating stripper wells withoutsubstantial loss of treating fluids into the formation.

More particularly, the treating fluid is a foamed emulsion comprising anorganic solvent for dissolving paraffins, and preferably alsoasphaltenes, an aqueous liquid, an inert gas, and sufficient of asurface active agent to maintain the stability of the treating fluid asa foamed emulsion under conditions of agitation while allowing saidfoamed emulsion to degas and separate into two continuous liquid phasesunder quiescent conditions. Typically and preferably, the aqueous liquidis nonacidic and nonformation-damaging, and the emulsion comprisesdiscontinuous gaseous and solvent phases within the aqueous phase. Also,in use in a formation, the treating fluid usually comprises, as liquids,about 0.5 to 70, preferably 5 to 30, volume percent of the solventphase, about 30 to 99, preferably 75 to 95, volume percent of theaqueous phase, and about 0.01 to 10, preferably 0.01 to 4, volumepercent of the surface active agent. In the foamed state, the treatingfluid contains a gaseous component usually in a concentration of about 1to 95, preferably 30 to 93, volume percent of the treating fluid.

The gas used to generate the foam can be any inert gas, although it ispreferred to use an easily available gas such as nitrogen. Althoughstimulation fluids are commonly foamed by pumping a gas containing acombustion-supporting component, such as air, into the fluid andagitating the mixture, the danger of a spark igniting volatilehydrocarbon vapors in the well and surrounding areas makes the use ofcombustion-supporting gases hazardous. The present inventionadvantageously removes this hazard from the drilling site by using aninert gas to build and support the foamed emulsion.

The aqueous component can be fresh water but is preferably a brineformulated by adding to water sufficient of a salt which prevents theswelling of clays, i.e., by adding sufficient quantities of such saltsto match the ionic strength of the brine to that of the connatereservoir waters and thus render the brine nonformation-damaging.Typically, it will be found that, to prevent formation damage, theaqueous component of the treating fluid of the invention will contain atleast 2,000 ppmw of a salt which prevents the swelling of clays in theformation. Potassium chloride is the preferred salt for this purpose,but sodium chloride is also suitable. Alternatively connate waterswithdrawn from the reservoir can be used as the aqueous component of thefoamed emulsion.

The organic solvent component used in the foamed emulsion compositioncan be a hydrocarbon solvent, halogenated hydrocarbon, or a polarsolvent or mixtures thereof, which solvents are capable of dissolvingparaffins and preferably both paraffins and asphaltenes to at least someextent. Preferably the solvent component will have a high flash pointand low volatility. Solvents which react with water to form acids oracid precursors should be avoided in the practice of this invention.

Hydrocarbon solvents such as petroleum solvents, petroleum ether,petroleum naphtha, gasoline, petroleum spirit, varnish makers' andpainters' naphtha, mineral spirits, kerosene, turbine fuel, highsolvency petroleum naphthas, butanes, 2,2-dimethylbutane, n-hexane,isohexane, n-heptane, isooctane, isoheptane, pentene-1, pentene-2, mixedpentenes, isoheptene, isooctenes, naphthas, benzene, toluene, toluenesubstitutes, xylene, solvent naphthas, ethylbenzene, diethylbenzene,isopropylbenzene, amylbenzene, diamylbenzene, triamylbenzene, tetraamylbenzene, dikerylbenzene-12, amyltoluene, cyclohexane,methylcyclohexane, tetrahydronaphthalene, decahydronaphthalene,diphenyl, coal-tar creosote, turpentine, terpene solvents, dipentene,pinene, p-cymene, p-methane, pine oils, tall oils, and crude oils aresuitable.

Halogenated hydrocarbons such as dichloromethane, carbon tetrachloride,ethyl chloride, ethylene chlorobromide, ethylene dichloride,dichloroethylene, B-trichloroethane, trichloroethylene, trichloroethane,1,1,2,2-tetrachloroethane, tetrachloroethylene, pentachloroethane,hexachloroethane, isopropyl chloride, allyl chloride, propylenedichloride, mixed amyl chloride, n-amyl chloride, dichloropentanes,n-hexyl chloride, monochlorohydrin, dichlorohydrin, epichlorohydrin,glycerol alpha-monochlorohydrin, glycerol alpha,-gamma dichlorohydrins,monobromobenzenes, dibromobenzene, monochlorobenzene, o-dichlorobenzene,trichlorobenzene, d-chloronaphthalene, monoamyl chloronaphthalene,diamyl chloronaphthalene, dichloroethylether, dichlorodiisopropyl ether,triglycol dichloride, halowax oils, dichlorodifluoromethane,difluorochloroethane, fluorodichloromethane, fluorotrichloromethane,trifluorotrichloroethane, dichlorotetrachloroethane, and ethylidenefluoride can be used.

While some polar solvents are miscible with water, mixtures of polarand/or nonpolar solvents containing miscible solvents can be immisciblewith water. Polar solvents immiscible with water and immiscible mixturesthereof can be employed, which include alcohols, ketones, ethers, andesters. Alcohols such as methanol, ethanol, n-propanol, isopropanol,n-butanol, isobutanol, sec-butanol, tert-butanol, fusel oil, primaryamyl alcohol, pentasol, n-amyl alcohol, sec-amyl alcohol, sec-n-amylalcohol, methyl amyl alcohol, 2-ethylbutyl alcohol, heptanol-2,heptanol-3, 2-ethylhexanol, capryl alcohol, nonyl alcohol, nonyl alcoholderivatives, diisobutylcarbinol, n-decanol, undecanol, trimethylnonylalcohol, tetradecanol, heptadecanol, benzyl alcohol, cyclohexanol,methylcyclohexanol, trimethylcyclohexanol, 4-tert-amyl cyclohexylalcohol, dimethyl tolyl carbinol, ethylene glycol, propylene glycol,diethylene glycol, dipropylene glycol, trimethyl glycol, triethyleneglycol, polyethylene glycols, polypropylene glycol 150, 2-methyl-2,4-pentane-diol, glycerol, terpene alcohol, and alphaterpineol areuseful.

Ketones such as methyl acetone, methyl ethyl ketone, methyl n-proplyketone, methyl isobutyl ketone, methyl n-amyl ketone, ethyl butylketone, di-n-propyl ketone, methyl hexyl ketone, diisobutyl ketone,diacetone alcohol, acetonyl acetone, cyclohexanone, and methylcyclohexanone are suitable.

Ethers including isopropyl ether, n-butyl ether, diamyl ether, n-hexylether, ethylene glycol monomethyl ether, mono and dialkyl ethers ofethylene glycol and their derivatives marketed by Union CarbideCorporation under the trademark "Cellosolve," ethylene glycolmono-n-butyl-ether, ethylene glycol monophenyl ether, ethylene glycolmonobenzyl ether, a series of glycol monoethers marketed by The DowChemical Company under the trademarks "Dowanol" 4, 2, 3 and diethyleneglycol monomethyl ether, diethylene glycol monoethyl ether, diethyleneglycol monobutyl ether, diethyl acetal, 1,2-propylene oxide,1,4-dioxane, methylal, 2-methyl furan tetrahydrofurane,2,3-dihydropyran, pentamethylene oxide, trioxane, terpinyl methyl ether,terpinyl ethylene glycol ether, dichloroethyl ether, triglycoldichloride, glyceryl d-monomethyl ether, glyceryl d,γ-dimethyl ether,glyceryl d-mono-n-butyl ether, glyceryl d,monoisamyl ether, and glyceryld-diisoamyl ether can be used.

Examples of esters which can be employed are ethyl acetate, n-propylacetate, isopropyl acetate, n-butyl acetate, sec-butyl acetate, isobutylacetate, amyl acetate, sec-amyl acetate, pentacetate, methyl amylacetate, 2-ethyl butyl acetate, cyclohexyl acetate, methyl cyclohexanylacetate, ethylene glycol monoacetate, glycol diacetate, ethylene glycolmonoethyl ether acetate, ethylene glycol monoethyl ether acetate,n-butyl propionate, methyl butyrate, n-butyl butyrate, ethylhydroxy-iso-butyrate, diethyl carbonate, diethyl oxalate, dibutyloxalate, and diamyl oxalate.

The preferred solvents for use in the practice of this invention arehighly aromatic and have a flash point above 100° F., as highly aromaticsolvents tend not to form sludges by precipitating asphaltenes out ofcrude oils as aliphatic solvents do. A solvent having a high flash pointis preferred for reasons of safety.

Generally, suitable surface active agents for use in the practice ofthis invention are those well known to practioners of the art andinclude amphoteric, non-ionic, cationic, and anionic surface activeagents. Such agents are known to alter the interface between liquid andgas phases or between two immiscible liquid phases. As some surfaceactive agents are effective for altering one type of interface but notanother, while other surface active agents are effective for both kindsof interface, the surface active component used in this invention cancomprise a single chemical compound or a mixture of compounds.

Among the useful surface active agents are those selected from the groupconsisting of cocoamide betaine, octylphenoxypolyethoxy ethanol,cocoylamidealkylamine, N-cocotrimethyl-ammonium chloride,bis(2-hydroxyethyl) cocoamine oxide, and sodium laurylsulfoacetate.

Surface active agents are often commercially available as a solution inwater or some other solvent at less than 100 percent by weight activity,for example, 30 to 50 percent active. In this discussion, theconcentration of the surface active agents is expressed in terms of thetotal amount of active material in the total liquid phase of thecomposition. Since the amount of surface active agent employed is smallcompared to the amount of the aqueous and other components of the foam,the amount of water or other solvent contributed to the foam compositionby less than 100 percent active surface active agents is small and isignored.

It will be understood that surface active agents will vary considerablyin effectiveness, depending, for example, on the choice of solvent andaqueous component of the treating composition, as well as on thecomposition of the connate water and/or crude oil within the well. Theeffectiveness will also depend on the nature of the surface activeagent. As an illustration, anionic surface active agents can usually beused only when their activity as surface active agents is not inhibitedby the salt content of the connate water.

Despite the variance to be expected in the efficacy of different surfaceactive agents, it is nevertheless readily ascertainable whether or not agiven surface active agent will prove useful for treating a givensubterranean formation. In the preferred embodiment, for example, onewould blend to form a sample emulsion of about 100 to 150 milliliters involume a sample of an aqueous component having an ionic strengthmatching the ionic strength of the connate water in the formation with asample of the highly aromatic solvent desired for dissolving paraffinsand with a sample of the crude oil in the formation to be treated. Thismixture is then admixed with a sample of the surface active agent to betested, and the combined ingredients are then subjected to intenseagitation to determine by visual inspection whether or not a stableemulsion forms. Assuming a stable emulsion does form, it is allowed tostand at rest in a graduated cylinder or other suitably elongated vesselto determine if the emulsion separates into two distinct, continuousphases within about 5 to 30 minutes. The time required for an emulsionto separate is a function of the height of the sample undergoingseparation. A laboratory sample that is only a few inches high in aone-inch high graduated cylinder separates in between 5 and 30 minutes,but will require between 0.5 and 24 hours to separate in a well wherethe column of emulsion is several feet in height. An emulsion which hasnot substantially separated within 30 minutes, therefore, indicates thatthe time for separation in a well will be so lengthy as to incurundesirable and expensive down-time before production can be resumed.Assuming the emulsion proves satisfactory by these tests, it is thenfoamed and employed in the reservoir or formation as a foamed emulsion.

If desired, prior to use, the foaming capacity of the emulsion may bedetermined by first foaming the emulsion, allowing it to stand, andmeasuring the time required for one half of the liquid in the foamedcomposition to drain from the foam.

To assure that the well-treating fluid can be readily pumped from thewellbore once the paraffin deposits have been cleaned from the well, theformation, and/or the service vessels and conduits, it is a criticalfeature of the invention that the surface active agent be provided in anamount that will stabilize the foamed emulsion as an emulsion underconditions of agitation but allow spontaneous breakdown under quiescentconditions, preferably within a period of time not less than about 0.5hour and not more than 24 hours. The foam will spontaneously die downand the emulsion will substantially separate when the treating fluid isat rest, the separated phases having viscosities substantially less thanthat of the oil-in-water emulsion. For use in producing wells,dissipation of the foam will facilitate various production operationssuch as determining fluid levels and pumping. The separated phases canthen be quickly and easily produced along with formation fluids from thewellbore without reduced flow potential.

Surface active agents can be found that will effectively enhanceformation of a foamed solvent emulsion from a non-acidified aqueoussolution formulated to have an ionic strength similar to that of theconnate waters in the reservoir to be tested and a hydrocarbon solventsuitable for dissolving paraffins and asphaltenes. The emulsion shouldfoam in the presence of an inert gas component administered underconditions of agitation and should remain a stable foamed emulsion underconditions of agitation, such as injection and circulation through thewellbore, annulus, and surface conduits servicing the well, but theemulsion should remain sufficiently destabilized to spontaneouslyseparate into aqueous-rich and solvent-rich liquid phases when injectionof the well-treating fluid has been stopped for a desired period oftime, for example, for about half an hour or more, so that the viscosityof the separated phases is substantially less than that of the emulsion.

The foam can be generated by combining the liquid ingredients and thesurface active agents in any desired order and introducing the gas intothe liquid with agitation. For convenience, a volume of water is usuallyplaced in a suitable mixing container and the desired salts are stirredin to make up the aqueous solution. Next, the surface active agents aremixed into the aqueous solution in any order desired or simultaneously.Next, the organic solvent component is added to the mixing container.While the resulting mixture is agitated, the inert gas is introduced toform the foam. While the foam can be prepared batchwise, it is alsopossible to prepare it in a continuous operation wherein the aqueoussolution and the mixture of surface active agents is introduced into aconduit at the same time as the organic solvent, and the gas isintroduced into the conduit as the emulsified mixture passes through it.The composition can be suitably agitated by passing it through a staticmixer located in the conduit downstream of the point or points ofaddition. The foam formed is then delivered to a point of use.

In removing paraffin deposits from wells and the conduits associatedtherewith, the foam can be introduced into the unit into contact withthe paraffin deposits and allowed to stand for a length of timesufficient to remove the deposit. Preferably, however, the foam iscontinuously passed through the unit, for example, a conduit, during thetreatment. In treating wells and/or the surrounding subterraneanreservoir, the foam can be introduced to the bottom of the well via aconduit suspended in the well or via the annulus between such a conduitand the sidewall of the well. At the bottom of the well, the foam can becirculated back to the surface or, by applying a pressure to the foamthat exceeds the reservoir pressure, the foam can be forced out into thereservoir if desired to dissolve paraffinic plugs that extend radiallyfrom the wellbore into the formation. Since the treating fluidpreferably contains no acid additive, the danger of depositingiron-bearing mineral deposits at depth into the formation is minimizedwhile swelling of clays is prevented due to the ionic compatibility ofthe aqueous component of the treating fluid with reservoir waters.

The composition and method of the invention are most advantageouslyemployed when the injected foamed emulsion is allowed, after contactwith the paraffinic deposits under agitated conditions, to stand underrelatively quiescent conditions so that the emulsion degasses andsubstantially separates into two liquid phases. These embodiments of theinvention take advantage not only of the separation and anti-gellingproperties of the foamed emulsion, but also of the relatively lowviscosity of the separated liquid phases. An embodiment of the inventionwhich takes advantage of these properties is directed to certainproducing wells wherein the emulsion is permitted to stand during thetime period separating the dissipation of a gas drive and initiation ofa mechanical lift. In a producing well, one may, as described above,employ a foamed emulsion by either of two general methods. The firstinvolves forcing the foamed emulsion under applied pressure into thewell and out into the formation, and then recovering the emulsion whenthe applied pressure is removed and the emulsion is driven back throughthe well into production. The second, and more preferable method, is toinject the foam into the well, then circulate the foam through theannulus to the surface, with the aid of back pressure from theformation, and, when the treatment is complete, then return the well toproduction to take advantage of the gas drive provided as the foambreaks down. In either embodiment, it is possible to operate withoutpermitting the foam to stand under relatively quiescent conditions, butin many if not most situations, the foam will stand under relativelyquiescent conditions during the time period commencing from the time theenergy of the gas drive is depleted until the time a pump or othermechanical lift is employed to remove the emulsion and produced liquids.Since this time period is generally sufficient to permit substantial(and occasionally complete) degassing as well as substantial (andoccasionally complete) separation into a two-phase liquid, advantageswill be gained in that, first, the separation prevents the emulsion fromreacting with formation fluids to form gels or other highly viscousmaterials, and second, the viscosity of the two-phase liquid issubstantially lower than that of the original emulsion. These twoadvantages allow for ready removal of the injected well-treating fluid,using ordinary pumps and the like.

In another embodiment of the invention, when the composition and/ormethod of this invention is used to remove paraffin deposits fromdepleted stripper wells, a technique employing alower pressure on thecirculating treating fluid in the wellbore than exists in the formation,for example, between about 10 and 1,500 p.s.i.g. lower, preferably 100to 500 p.s.i.g. lower, can be used to dissolve paraffin deposits withoutdanger of blowouts. The particular advantage of this technique is thatthe higher formation pressure will inhibit penetration of the treatingcomposition into the formation and will prevent insoluble components ofthe paraffinic sludge from remaining once paraffin and asphaltenecomponents have been dissolved from the deposit plugging the formationby blowing them out of the face of the wellbore and into the circulatingtreating fluid.

In yet another embodiment, the foamed emulsion is used to clean paraffindeposits from industrial units such as the tubing of heat exchangers andconduits by contacting the deposits with the foamed emulsion, preferablyunder conditions of agitation.

The invention is further illustrated by the following examples which areillustrative of various aspects of the invention and are not intended aslimiting the scope of the invention as defined by the appended claims.

EXAMPLES 1 TO 24

To test the foaming, emulsifying, and self-breaking tendencies of foamedemulsion compositions stabilized by the surface active agents of thisinvention, a series of tests are conducted. Each composition comprisingan aqueous solution, a solvent and one or more surface active agents istested first as an emulsion to determine its stability and the rate atwhich the phases separate upon standing. Then the emulsion is foamed bystirring in air, and the height and drain half life of the foam aredetermined to test the stability of the foam. Into some samples of thecomposition, a portion of crude oil contaminant is added to ascertainwhether contact of the well-treating fluid with the standing column ofoil in the reservoir will adversely affect its foaming, emulsifying andself-breaking tendencies.

More particularly, a measured quantity of surface active agent is placedinto a close-topped graduated cylinder to which is added a sufficientamount of an aqueous solution containing 3 percent by weight ofpotassium chloride to fill the graduated cylinder to the 70 millilitermark. Then Super High Flash Naphtha, an aromatic solvent having a flashpoint between 100° and 200° F. manufactured by Union Oil Company,Chemicals Division, is added to the aqueous mixture in an amountsufficient to fill the cylinder up to the 100 milliliter mark. Thecylinder is closed and shaken to disburse the surfactant into thesolvating phases and the mixture is allowed to stand for one minute.Then the mixture is shaken again exactly 25 times and allowed to stand.

The absence or appearance of an interface between the aqueous andorganic solvent phases is noted and the position of the interface as itmoves up the height of the cylinder is recorded at timed intervals of 1minute, 5 minutes, 15 minutes, 30 minutes and, occasionally again afteran interval of 24 hours from the time the mixture was last agitated. Inall cases, the sharpness of the interface is noted. The slower thevertical movement of the interface up the height of the graduatedcylinder, the more stable the emulsion.

To test for the stability of the test mixtures as a foam, the content ofeach graduated cylinder is poured into an 800 milliliter beaker andstirred vigorously with a manually operated egg beater for 2 minutes toform a foam. The resulting foam is then transferred into a500-milliliter graduated cylinder having a diameter of about 4.6centimeters. To determine the drain half-life of the foam, the timerequired for one-half the liquid volume to drain from the foam isrecorded. If no crude oil has been added to the mixture, the drainhalf-life will be the time required for 50 milliliters to drain from themixture. If crude oil has been added, the drain half-life will be thetime required for 50 milliliters plus one half the amount of the addedcrude to drain from the mixture. The longer the drain half-life, themore stable the foamed emulsion. The height of the foam in the cylinderis also recorded. A high-rising foam indicates ease of foaming.

Surface active agents in the amounts indicated below in Table I wereused alone or in combination in Tests 1 to 24 to generate foamedemulsions according to the laboratory procedures set forth hereinabove.

                  TABLE I                                                         ______________________________________                                        Agent                               Activity                                  Designation                                                                            Type      Formula          %*                                        ______________________________________                                        A        Amphoteric                                                                              Cocoamide betaine                                                                              45                                        B        Non-ionic Octylphenoxypolyethoxy                                                                         100                                                          ethanol                                                    C        Cationic  Cocoylamidealkylamine                                                                          50                                        D        Cationic  N--Cocotrimethyl-                                                                              50                                                           ammonium chloride                                          E        Cationic  bis(2-hydroxyethyl)-                                                                           50                                                           cocoamine oxide                                            F        Anionic   Sodium laurylsulfoacetate                                                                      70                                        ______________________________________                                         *Percent active ingredient by weight in water.                           

In Table II, the results obtained in Tests 7 to 24 using variouscombinations of the surface active agents are compared with the resultsattained in Tests 1 to 6 by using each of the surface active agentsalone. Agents A, C, and D are capable of generating suitably stableemulsions when used alone, and foams of these emulsions exhibit thegreatest height of any produced by the surface active agents tested aswell as possessing drain half-lives unsurpassed by any of the twocomponent combinations used in Tests 7 to 18. Agent A is amphoteric andagents C and D are cationic. On the other hand, agent B, the non-ionicagent, although useful for preparing a highly stable emulsion, isinferior when used alone as a foaming agent. Agent F, the anionic agent,is not suitable as either an emulsifying or a foaming agent.

However, as is seen in Tests 13 to 18, agent B possesses thecharacteristic, when used in combination with agents A, C, and D, oftending to stabilize the emulsions and destabilize the foams, the latterof which are seriously impaired both in maximum foam height and in drainhalf-life. When agent B is used in combination with agent E, the resultsare somewhat contradictory. Comparison of the results of Tests 5 and 16shows that foam height is slightly increased but drain half-life isslightly decreased when agent B is added to agent E.

In Tests 7 to 10, as the proportion of agent B added in combination withagent A, C, D, or E is increased, the stability of the emulsion iscorrespondingly increased. When 0.35 milliliter of B is used incombination with 0.75 to 1.0 milliliter of A, C, D, or E, the rate atwhich the phases separate upon standing is greater than when 0.7milliliter of agent B is used in combination with the same amounts of A,C, D, or E in Tests 13 to 16.

In the preferred practice of this invention, surface active agentsshould be chosen so as to promote a high foaming, well-formed emulsionunder conditions of agitation but so as to allow rapid breakdown of thefoam and spontaneous separation of the emulsion once circulation hasstopped. As illustrated in Tests 7 to 24, a combination of surfaceactive agents can be readily found that does not, on the one hand,overly stabilize the emulsion and thereby hinder its self-breakingcharacteristic or, on the other hand, overly depress the foam generatingcharacteristics of the mixture. The results of these experimentsindicate that generally in combinations of surface active agents theproportion of agent B, or other similar non-ionic surface active agent,to agents having ionic charges should not be greater than the ratiosbetween 1:0.1 and 1:0.5 by volume for best self-breaking characteristicsin the emulsion.

The results of Tests 19 to 24, which incorporate 5 milliliters of crudeoil into the aqueous-solvent emulsions, demonstrate that agents A, B,and D form stable emulsions possessing good foaming and self-breakingcharacteristics in the presence of crude oil. Agent E, the cationicsurface active agent, on the other hand, tends to overly stabilize theemulsion in the presence of crude oil, thereby hindering itsself-breaking characteristics. And agent F, the anionic agent, preventsfoaming. These tests illustrate that for the characteristics desired inthe combination of this invention, when the reservoir possesses thecrude oil and connate waters similar to those used in these testssurface active agents such as A, D, and B should be used, while anionicsurface active agents such as agent F should be avoided, especially incompositions having potassium ions or similarly acting ions in solution.

                                      TABLE II                                    __________________________________________________________________________    EMULSION AND FOAM STABILITY TEST                                                                                          FOAM STABILITY TESTS                              EMULSION TESTS                                                                           INTERFACE HEIGHT IM cm**   MAXIMUM***              TEST                                                                              SURFACE ACTIVE                                                                            INTERFACE  AT TIME IN MINUTES**                                                                           DRAIN 1/2-LIFE                                                                          FOAM HEIGHT             No. AGENTS      DESCRIPTION                                                                              1   5   15  30   (min)     (cm)                    __________________________________________________________________________    1   2 ml A      Sharp      1.81                                                                              8.6 11.3                                                                              12.1 2'45"     23.1                    2   0.7 ml B    Barely Detect                                                                            0.4 1.8 4.9  9.2 0'15"     13.8                    3   1.5 ml C    Sharp      1.1 6.0 10.6                                                                              11.3 2'30"     24.8                    4   1.5 ml D    Sharp      1.5 6.0 11.0                                                                              12.1 3'00"     28.9                    5   1.5 ml E    Sharp      0.8 3.6 7.0 11.0 1'25"     19.8                    6   1 gm F      Sharp      10.4                                                                              10.6                                                                              10.6                                                                              10.8 No Foam   No Foam                 7   1 ml A, 0.35 ml B                                                                         Sharp      0.2 1.5 6.2  9.7 --        --                      8   0.75 ml C. 0.35 ml B                                                                      Sharp      0.9 4.0 10.2                                                                              11.0 --        --                      9   0.75 ml D, 0.35 ml B                                                                      Sharp      0.9 4.8 10.8                                                                              11.3 --        --                      10  0.75 ml E, 0,35 ml B                                                                      Sharp      0.8 2.2 6.6 10.2 --        --                      11  0.5 gm F, 0.35 ml B                                                                       Barely Detect                                                                            0.2 2.0 5.1 10.2 --        --                      12  1 ml A, 0.75 ml D                                                                         Sharp      1.6 9.0 11.7                                                                              12.4 --        --                      13  1 ml A, 0.7 ml B                                                                          Sharp      0.2 1.8 4.9  9.2 0'35"     17.9                    14  0.75 ml C, 0.7 ml B                                                                       Sharp      0.3 2.4 6.6  8.1 0'30"     14.3                    15  0.75 ml D, 0.7 ml B                                                                       Sharp      0.3 3.3 8.4 10.2 0'10"     15.1                    16  0.75 ml E, 0.7 ml B                                                                       Barely Detect                                                                            0.2 1.5 No  No.sup.1                                                                           0'07"     20.4                    17  0.5 gm F, 0.7 ml B                                                                        Barely Detect                                                                            0.2 0.8 No  No.sup.2                                                                           No Foam   No Foam                 18  1 ml A, 0.75 ml D,                                                                        Sharp      0.8 2.9 8.6 10.6 0'05"     11.0                        0.35 ml B                                                                 19  1 ml A, 0.7 ml B,                                                                         --         0.8 2.4 5.9  9.3 3'28"     20.6                        5 ml W*                                                                   20  0.75 ml B, 0.7 ml B                                                                       --         0.4 1.6 4.6  8.2 1'17"     15.1                        5 ml W                                                                    21  0.75 ml D, 0.7 ml B,                                                                      --          .9 1.5 6.2  9.2 0'07"     13.2                        5 ml W                                                                    22  0.75 ml E, 0.7 ml B,                                                                      --         ND  ND  0.9  1.6 3'40"     17.6                        5 ml W                                                                    23  0.5 gm F, 0.7 ml B,                                                                       --          .8 2.4 7.3 12.1 No Foam   No Foam                     5 ml W                                                                    24  1 ml A, 0.75 ml D,                                                                        --          .4 1.8 4.6  8.4 7'35"     27.5                        0.7 ml B, 5 ml W                                                          __________________________________________________________________________     .sup.1 24 hours  interface height 9.1                                         .sup.2 24 hours  interface height 12.1                                        *W stands for crude oil                                                       **Graduated Cylinder  100 ml. 2.3 × 18.3 cm (@ 100                      ***Graduated Cylinder  500 ml. 4.6 cm × 27.5 (@ 500 ml)            

EXAMPLES 25 TO 31

In Tests 25 to 30, the foaming characteristics of surface active agentsdissolved in an aqueous solution containing 3 percent by weight ofpotassium chloride but no aromatic solvent are compared. The results ofthese tests summarized in Table III show that compositions containingagents A, C, and D produce less stable foams in the absence of thesolvent component, while agents B and E produce more-stable foams asmeasured by drain half-life.

In Test 30, the saline solution to which agent F is added produces nofoam, but as Test 31 shows, addition of the same amount of agent F todistilled water produces excellent foaming capability. For anionicsurface active agents, such as agent F, the presence of ionic componentssuch as potassium chloride in a concentration as high as 3 percent byweight of the aqueous solution prevents foaming. It may be concluded,therefore, that agent F, and other similar acting anionic surface activeagents, can prove effective for the practice of this invention when usedin mixtures containing aqueous components of very little ionic strength,despite their ineffectiveness in mixtures containing as much as 3percent by weight of potassium chloride.

                  TABLE III                                                       ______________________________________                                        FOAMING CHARACTERISTICS OF SURFACE                                            ACTIVE AGENTS                                                                 Surface Active          Maximum                                               Agent        Drain 1/2-Life                                                                           Foam Height (cm)                                      ______________________________________                                        2.0 ml A     1'25"      22.0                                                  0.7 ml B       54"      25.3                                                  1.5 ml C     1'10"      24.8                                                  1.5 ml D     1'45"      27.8                                                  1.5 ml E     3'45"      32.2                                                  1 gm F       No Foam    No Foam                                               1 gm F*      6'56"      34.2                                                  ______________________________________                                         *Distilled water replaced the aqueous solution of 3 wt. % KCL in this         mixture.                                                                 

The effectiveness of surface active agents used in the practice of thisinvention will be influenced by the chemical properties of the aqueousand solvent components of the emulsion and of the crude oil in place inthe reservoir. For best results, therefore, surface active agents shouldbe selected using an emulsion made from (1) a solvent component fordissolving paraffins and asphaltenes, (2) a sample of crude oil from thereservoir to be tested, and (3) an aqueous component formulated to matchthe ionic strength of the connate waters of the reservoir to be tested.Alternatively, a sample of connate waters withdrawn from the reservoircan be used as the aqueous phase if such waters are to be used as theaqueous component of the emulsion. The surface active agent should bechosen so as to ensure stability of the emulsion such that not more thanabout 50 volume percent of the total emulsion separates into asubstantially continuous lower liquid phase within 15 minutes from thetime that agitation of the emulsion has stopped. When beaten for twominutes, foam of an emulsion having the above-described stability shouldalso have a drain half life of not less than 0.5 minute.

Establishing the chemical environment during experimentation in whichthe surface active agents will function during use will enable oneskilled in the art to select a surface active agent or combination ofsurface active agents that will impart to the well-treating compositionas closely as possible the characteristics desired, such as the time theemulsion should require to separate into two liquid phases aftercirculation or agitation has ceased. For example, if routine oremergency shutdown of the facilities circulating the treating fluid isanticipated for brief periods of time, it may be desirable to formulatea treating solution for which breakdown of the emulsion is less rapidthan would be desired if no stoppage of circulation is anticipated.

The well-treating fluid and process for its use as above describedprovide significant advantages. Unlike a water-free foamed solvent,which can change drastically in rheological character when contacted byconnate water, the foamed oil-in-water emulsion of this inventionmaintains a substantially uniform viscosity despite contact with connatewater so long as the fluid is agitated. And under quiescent conditions,the foamed emulsion spontaneously separates into two liquid phases oflower viscosity than the emulsion.

A second advantage of the oil-in-water emulsion lies in the protectionthe exterior phase affords to the solvent droplets against contaminationby oil in the reservoir during placement of the treating fluid into thelower regions of the wellbore where paraffin deposits usuallyaccummulate. Unlike the water-in-oil emulsion, therefore, theoil-in-water emulsion insulates the solvent against dilution by oil inthe reservoir.

On the other hand, the non-formation damaging aqueous component of thefoamed solvent emulsion of this invention offers further advantages foruse with iron or clay-containing formations. Containing a non-acidifiedaqueous component, the preferred foamed emulsion prevents dissolution ofiron-bearing materials and, therefore, prevents resultant deposition ofiron-containing compounds that would reduce formation permeability.Moreover, the preferred aqueous component used in the emulsion in thisinvention does not damage the clays in the reservoir. To avoid clayswelling that impairs permeability, the aqueous component is formulatedto match the ionic strength of connate waters in place. Therefore afoamed emulsion containing a non-acidified, ionically compatible aqueouscomponent has specific advantages for use in iron or clay-bearingformations.

Although this invention has been described in conjunction with apreferred embodiment thereof, it is evident that many alternatives,modifications, and variations will be apparent to those skilled in theart in light of the foregoing description. Accordingly, it is intendedto embrace all such alternatives, modifications, and variations thatfall within the scope of the claims.

We claim:
 1. A foamed oil-in-water emulsion for cleaning paraffindeposits from subterranean locations penetrated by a wellbore, saidfoamed emulsion comprising an organic solvent for paraffins, saidsolvent being selected from the group consisting of halogenatedhydrocarbons of low volatility and highly aromatic hydrocarbons, and anon-acidic aqueous liquid containing not less than 2,000 ppm by weightof dissolved ionic components selected from the group consisting ofsodium chloride and potassium chloride, and sufficient of a surfaceactive agent selected to maintain the stability of said foamed emulsionunder conditions of agitation while allowing said foamed emulsion todegas and separate into two substantially continuous liquid phases underrelatively quiescent conditions.
 2. An emulsion as defined in claim 1wherein the organic solvent comprises a substantially aromatichydrocarbon possessing a boiling point above about 100° F.
 3. A foamedoil-in-water emulsion as defined in claim 1 wherein a 100 to 150milliliter sample of said emulsion formed of said aqueous liquid,solvent, and surface active agent under conditions of agitationundergoes separation, while standing as an elongated column of liquid ofabout 15 centimeters height, of between about 5 and 50 volume percent ofsaid emulsion into a substantially continuous lower liquid phase withinabout 5 minutes from the time that agitation of the emulsion hasstopped, while a foamed emulsion formed by vigorously stirring the inertgas into said emulsion has a drain half-life of not less than 0.5minute.
 4. An emulsion as defined in claim 1 wherein said foamedemulsion further comprises between about 30 and about 93 percent byvolume of total treating composition of inert gas.
 5. An emulsion asdefined in claim 4 wherein said inert gas is nitrogen.
 6. An emulsion asdefined in claim 4 wherein the surface active agents are selected fromthe group consisting of cocoamide betaine, octylphenoxypolyethoxyethanol, cocoylamidealkylamine, and N-cocotrimethylammonium chloride. 7.An emulsion defined in claim 4 wherein said surface active agents areselected from the group consisting of cocoamide betaine,octylphenoxypolyethoxyethanol, cocoylamidealkylamine,N-cocotrimethylammonium chloride, and sodium laurylsulfoacetate.
 8. Anemulsion as claimed in claim 1 wherein said solvent comprises a solventfor paraffins and for asphaltenes.
 9. A foamed oil-in-water emulsion forcleaning paraffin and asphaltene deposits from subterranean locationspenetrated by a wellbore, said foamed emulsion comprising an organicsolvent for both paraffins and asphaltenes, said solvent being selectedfrom the group consisting of halogenated hydrocarbons of low volatilityand highly aromatic hydrocarbons, and a non-acidic aqueous liquidcontaining not less than 2,000 ppm by weight of dissolved ioniccomponents, and sufficient of a surface active agent selected tomaintain the stability of said foamed emulsion under conditions ofagitation while allowing said foamed emulsion to degas and separate intotwo substantially continuous liquid phases under relatively quiescentconditions.
 10. A foamed oil-in-water emulsion as defined in claim 9wherein a 100 to 150 milliliter sample of said emulsion formed of saidaqueous liquid, solvent, and surface active agent under conditions ofagitation undergoes separation, while standing as an elongated column ofliquid of about 15 centimeters height, of between about 5 and 50 volumepercent of said emulsion into a substantially continuous lower liquidphase within about 5 minutes from the time that agitation of theemulsion has stopped, while a foamed emulsion formed by vigorouslystirring an inert gas into said emulsion has a drain half-life of notless than 0.5 minute.
 11. An emulsion as defined in claim 10 whereinsaid foamed emulsion further comprises between about 30 and about 93percent by volume of total treating composition of inert gas and whereinsaid inert gas consists essentially of nitrogen.
 12. An emulsion asdefined in claim 11 wherein the surface active agents are selected fromthe group consisting of cocoamide betaine, octylphenoxypolyethoxyethanol, cocoylamidealkylamine, and N-cocotrimethylammonium chloride.13. A foamed oil-in-water emulsion for cleaning paraffin deposits fromsubterranean locations penetrated by a wellbore, said foamed emulsioncomprising an organic solvent for paraffins, said solvent being selectedfrom the group consisting of halogenated hydrocarbons of low volatilityand highly aromatic hydrocarbons, and an aqueous liquid consistingessentially of reservoir connate water, and sufficient of a surfaceactive agent selected to maintain the stability of said foamed emulsionunder conditions of agitation while allowing said foamed emulsion todegas and separate into two substantially continuous liquid phases underrelatively quiescent conditions.
 14. A foamed oil-in-water emulsion asdefined in claim 13 wherein a 100 to 150 milliliter sample of saidemulsion formed of said aqueous liquid, solvent, and surface activeagent under conditions of agitation undergoes separation, while standingas an elongate column of liquid of about 15 centimeters height, ofbeteween about 5 and 50 volume percent of said emulsion into asubstantially continuous lower liquid phase within about 5 minutes fromthe time that agitation of the emulsion has stopped, while a foamedemulsion formed by vigorously stirring an inert gas into said emulsionhas a drain half-life of not less than 0.5 minute.
 15. An emulsion asdefined in claim 13 wherein said foamed emulsion further comprisesbetween about 30 and about 93 percent by volume of total treatingcomposition of inert gas.
 16. An emulsion as defined in claim 15 whereinthe surface active agents are selected from the group consisting ofcocoamide betaine, octylphenoxypolyethoxy ethanol,cocoylamidealkylamine, and N-cocotrimethylammonium chloride.
 17. Aprocess for forming a well treatment fluid useful for removingparaffinic hydrocarbon deposits from subterranean locations penetratedby a wellbore, said process comprising (1) emulsifying finely divideddroplets of a hydrocarbon-dissolving solvent in a continuous aqueousphase containing not less than 2,000 ppm by weight of dissolved sodiumchloride or potassium chloride to form an oil in water emulsion, saidsolvent being selected from the group consisting of halogenatedhydrocarbons of low volatility and highly aromatic hydrocarbons, and (2)forming a stable foam from said emulsion by turbulently contacting saidfoam with a stream of inert gas, the foamed emulsion maintainingstability under conditions of agitation and undergoing relatively rapidand substantially breakdown into two liquid phases under conditions ofrest.
 18. The process defined in claim 17 wherein surface active agentsdissolved in said aqueous phase are used to aid in dispersing saiddroplets or solvent in step (1) and to form said foam in step (2), saidsurface active agents being selected from the group consisting ofcocoamide betaine, octylphenoxypolyethoxyethanol, cocoylamidealkylamine,N-cocotrimethylammonium chloride.